According to the International Energy Agency, the global demand for hydrocarbons is expected to keep increasing at least until 2040. Yet in Canada, during the past year or so, an unusually large number of major events—essentially all negative—affected the oil and gas industry. The departure of international companies, pipeline project delays, and unprecedented discounts on Western Canadian Select (WCS) are just some of the signs that the country’s oil and gas sector is facing serious challenges.

Research Paper prepared by Germain Belzile, Senior Associate Researcher at the MEI, and Jean Michaud, Associate Researcher at the MEI.

Highlights

According to the International Energy Agency, the global demand for hydrocarbons is expected to keep increasing at least until 2040. Yet in Canada, during the past year or so, an unusually large number of major events—essentially all negative—affected the oil and gas industry. The departure of international companies, pipeline project delays, and unprecedented discounts on Western Canadian Select (WCS) are just some of the signs that the country’s oil and gas sector is facing serious challenges.

Chapter 1 – Market Access

Lack of pipelines is the issue currently having the greatest financial impact on the oil and gas industry, over other factors, and affects not only the industry, but also provincial finances and the whole Canadian economy.

During the 2009-2012 period, when there were no evident pipeline constraints, WCS (the commonly used benchmark for Canadian oil) traded on average at a US$11.17 discount to WTI (the U.S. oil benchmark).

In 2018, the WCS vs. WTI discount peaked at US$50 per barrel, which led the Alberta government to impose production cutbacks of 325,000 barrels per day, temporarily easing the pain, but not solving the underlying problem.

A report published by RBC in May 2018 found that the cost of a sustained US$5/barrel larger-than-normal WCS-WTI price gap would be about C$4 billion to C$5 billion a year.

In 2018, for the first time, output exceeded pipeline capacity, and crude oil exports by rail exceeded 300,000 barrels per day by the end of the year, up from around 150,000 at the beginning of the year.

Transportation by rail may alleviate the problem, but it is not cheap: Moving oil by train to the U.S. Gulf Coast costs an extra 50% to 100% compared to moving it by pipeline.

Except for the lack of pipelines, there is no reason anymore for WCS to trade at a discount to WTI, since the U.S. is awash with very light oils from fracking and needs our heavier oils.

Improved access to tidewater would allow Canadian producers to service Asia, whose demand for oil is expected to increase by 9 million barrels per day by 2040, along with major increases in demand for natural gas.

Lack of pipelines also increases the cost of crude oil for Eastern Canadian refineries, with Canada importing approximately 670,000 barrels of crude oil per day in 2017, around half of which came from overseas.

Chapter 2 – Carbon Taxes

There are no valid reasons that justify a carbon tax being 50% higher than the de facto rate currently in effect in Quebec’s cap & trade system, as Alberta’s $30 carbon tax is—and even less to justify it being about twice as high as in Quebec, as the federal tax will be by 2022.

The carbon tax regimes now in force across Canada ignore a few realities: a) that carbon emissions are first and foremost a consumption problem; b) that while companies don’t vote, they may move to another jurisdiction (i.e., carbon leakage); and c) that Canada is a trading nation and does not live in isolation.

Alberta and Saskatchewan produce more carbon than they consume, and are therefore penalized by Canada’s production-based carbon taxes; B.C., Ontario, and Quebec all consume more carbon than they produce, and are thus favoured by Canada’s methodology.

It is pointless to shut down a CO2 emitting facility if the goods it produces are to be later imported or produced in another jurisdiction which does not have as strict pollution-control measures.

A strong argument against carbon border taxes is that they impinge upon free trade; a unilateral border-adjustment system could create a backlash, and might even lead to a trade war with our trading partners.

Any carbon tax should be compensated by an equivalent reduction of other taxes, preferably the ones that are the most destructive in economic terms: corporate taxes on profits and personal income taxes, for example.

Governments may not want to forego the carbon tax proceeds, but a tonne of CO2 not emitted in Canada or elsewhere in the world has the same impact on the climate. The purpose of a carbon tax should be to reduce carbon emissions, not to raise tax revenues from individuals and companies.

Allowing emitters to use all the tools available to them to achieve the stated goal, at the lowest possible cost, would reduce the adverse economic impact on the Canadian economy.

Chapter 3 – Regulations and Permitting Delays

Companies operating in Alberta point to the permitting delays observed in the province as a serious problem; compared to oil and gas producing American states, the province is not competitive in this regard.

When applying to drill on U.S. freehold land, permitting is always months faster than it is in Alberta, with Texas being the friendliest state.

Between 2014 and 2017, requests by stakeholders to be heard before a project is approved have doubled in relative terms, while the total numbers of applications for both wells and facilities fell by over 40%.

The pitfalls of social licence, by giving too much room to various groups, seem to have affected applications for facilities and wells, and are likely to be fuelling a loss of confidence in the existing process due to its unpredictability.

Extraordinary timelines also affect oil sands projects, with a typical in situ development in Alberta having a best-case approval timeline from the start of consultation through to the start of construction of 4 to 6 years.

Chapter 4 – Energy Corridors and First Nations Partnerships

An early example of an energy corridor was proposed in the 1970s from the Mackenzie River delta to Alberta and the United States. Revived in the early 2000s, it was later cancelled following the price drop for natural gas.

The presence of First Nations in the development of energy resources and energy corridors is now a fact of life, with the Indian Resource Council (IRC) now representing over 200 First Nations across the country.

Some of the main opposition to Bill C-48, the Oil Tanker Moratorium, is coming from First Nations-led groups promoting their own pipeline project, while the IRC is asking the federal government to put Bill C-69 on hold.

Two current examples of potential energy corridors are the corridor where the Eagle Spirit pipeline would be located, between Alberta and the BC coast, and the corridor where the Ontario-to-Quebec Gazoduq pipeline would be located.

Chapter 5 – Other Issues

Methane is a much more potent greenhouse gas than carbon dioxide. Alberta and British Columbia—the main gas producing provinces—are committed to reducing methane emissions by 45% by 2025.

From its inception early in 2017, the proposed Federal Clean Fuel Standard has been identified as duplicating existing provincial and federal emission reduction policies. It is essentially another carbon tax under different name.

Some research has shown that implementing renewable fuel standards led to an increase in food prices and a smaller reduction in global GHG emissions compared to other policy options.

There are over 120,000 inactive oil and gas wells in Western Canada, around three quarters of which are in Alberta and the remainder mainly in Saskatchewan, but also in British Columbia.

Reclaiming a well requires returning the surface land to its original state. Orphan wells are wells whose owners were unable or unwilling to plug the borehole and/or reclaim the site.

The graphs (Click to enlarge)

Research Paper prepared by Germain Belzile, Senior Associate Researcher at the MEI, and Jean Michaud, Associate Researcher at the MEI.

Highlights

According to the International Energy Agency, the global demand for hydrocarbons is expected to keep increasing at least until 2040. Yet in Canada, during the past year or so, an unusually large number of major events—essentially all negative—affected the oil and gas industry. The departure of international companies, pipeline project delays, and unprecedented discounts on Western Canadian Select (WCS) are just some of the signs that the country’s oil and gas sector is facing serious challenges.

Chapter 1 – Market Access

Lack of pipelines is the issue currently having the greatest financial impact on the oil and gas industry, over other factors, and affects not only the industry, but also provincial finances and the whole Canadian economy.

During the 2009-2012 period, when there were no evident pipeline constraints, WCS (the commonly used benchmark for Canadian oil) traded on average at a US$11.17 discount to WTI (the U.S. oil benchmark).

In 2018, the WCS vs. WTI discount peaked at US$50 per barrel, which led the Alberta government to impose production cutbacks of 325,000 barrels per day, temporarily easing the pain, but not solving the underlying problem.

A report published by RBC in May 2018 found that the cost of a sustained US$5/barrel larger-than-normal WCS-WTI price gap would be about C$4 billion to C$5 billion a year.

In 2018, for the first time, output exceeded pipeline capacity, and crude oil exports by rail exceeded 300,000 barrels per day by the end of the year, up from around 150,000 at the beginning of the year.

Transportation by rail may alleviate the problem, but it is not cheap: Moving oil by train to the U.S. Gulf Coast costs an extra 50% to 100% compared to moving it by pipeline.

Except for the lack of pipelines, there is no reason anymore for WCS to trade at a discount to WTI, since the U.S. is awash with very light oils from fracking and needs our heavier oils.

Improved access to tidewater would allow Canadian producers to service Asia, whose demand for oil is expected to increase by 9 million barrels per day by 2040, along with major increases in demand for natural gas.

Lack of pipelines also increases the cost of crude oil for Eastern Canadian refineries, with Canada importing approximately 670,000 barrels of crude oil per day in 2017, around half of which came from overseas.

Chapter 2 – Carbon Taxes

There are no valid reasons that justify a carbon tax being 50% higher than the de facto rate currently in effect in Quebec’s cap & trade system, as Alberta’s $30 carbon tax is—and even less to justify it being about twice as high as in Quebec, as the federal tax will be by 2022.

The carbon tax regimes now in force across Canada ignore a few realities: a) that carbon emissions are first and foremost a consumption problem; b) that while companies don’t vote, they may move to another jurisdiction (i.e., carbon leakage); and c) that Canada is a trading nation and does not live in isolation.

Alberta and Saskatchewan produce more carbon than they consume, and are therefore penalized by Canada’s production-based carbon taxes; B.C., Ontario, and Quebec all consume more carbon than they produce, and are thus favoured by Canada’s methodology.

It is pointless to shut down a CO2 emitting facility if the goods it produces are to be later imported or produced in another jurisdiction which does not have as strict pollution-control measures.

A strong argument against carbon border taxes is that they impinge upon free trade; a unilateral border-adjustment system could create a backlash, and might even lead to a trade war with our trading partners.

Any carbon tax should be compensated by an equivalent reduction of other taxes, preferably the ones that are the most destructive in economic terms: corporate taxes on profits and personal income taxes, for example.

Governments may not want to forego the carbon tax proceeds, but a tonne of CO2 not emitted in Canada or elsewhere in the world has the same impact on the climate. The purpose of a carbon tax should be to reduce carbon emissions, not to raise tax revenues from individuals and companies.

Allowing emitters to use all the tools available to them to achieve the stated goal, at the lowest possible cost, would reduce the adverse economic impact on the Canadian economy.

Chapter 3 – Regulations and Permitting Delays

Companies operating in Alberta point to the permitting delays observed in the province as a serious problem; compared to oil and gas producing American states, the province is not competitive in this regard.

When applying to drill on U.S. freehold land, permitting is always months faster than it is in Alberta, with Texas being the friendliest state.

Between 2014 and 2017, requests by stakeholders to be heard before a project is approved have doubled in relative terms, while the total numbers of applications for both wells and facilities fell by over 40%.

The pitfalls of social licence, by giving too much room to various groups, seem to have affected applications for facilities and wells, and are likely to be fuelling a loss of confidence in the existing process due to its unpredictability.

Extraordinary timelines also affect oil sands projects, with a typical in situ development in Alberta having a best-case approval timeline from the start of consultation through to the start of construction of 4 to 6 years.

Chapter 4 – Energy Corridors and First Nations Partnerships

An early example of an energy corridor was proposed in the 1970s from the Mackenzie River delta to Alberta and the United States. Revived in the early 2000s, it was later cancelled following the price drop for natural gas.

The presence of First Nations in the development of energy resources and energy corridors is now a fact of life, with the Indian Resource Council (IRC) now representing over 200 First Nations across the country.

Some of the main opposition to Bill C-48, the Oil Tanker Moratorium, is coming from First Nations-led groups promoting their own pipeline project, while the IRC is asking the federal government to put Bill C-69 on hold.

Two current examples of potential energy corridors are the corridor where the Eagle Spirit pipeline would be located, between Alberta and the BC coast, and the corridor where the Ontario-to-Quebec Gazoduq pipeline would be located.

Chapter 5 – Other Issues

Methane is a much more potent greenhouse gas than carbon dioxide. Alberta and British Columbia—the main gas producing provinces—are committed to reducing methane emissions by 45% by 2025.

From its inception early in 2017, the proposed Federal Clean Fuel Standard has been identified as duplicating existing provincial and federal emission reduction policies. It is essentially another carbon tax under different name.

Some research has shown that implementing renewable fuel standards led to an increase in food prices and a smaller reduction in global GHG emissions compared to other policy options.

There are over 120,000 inactive oil and gas wells in Western Canada, around three quarters of which are in Alberta and the remainder mainly in Saskatchewan, but also in British Columbia.

Reclaiming a well requires returning the surface land to its original state. Orphan wells are wells whose owners were unable or unwilling to plug the borehole and/or reclaim the site.